Composites for use in stimulation and sand control operations

ABSTRACT

A composite having a solid particulate and a surface modifying treatment agent on the solid particulate wherein the surface modifying treatment agent has a hydrophobic tail and an anchor for adhering the hydrophobic tail onto the solid particulate. The anchor may be metal and the hydrophobic tail may be an organo-silicon material, a fluorinated hydrocarbon or both an organo-silicon material and a fluorinated hydrocarbon. The composite may be used as a proppant in a hydraulic fracturing operation as well as a sand control particulate in a gravel packing operation. The presence of the surface modifying treatment agent on the surface of the solid particulate reduces the generation of fines and dust as well as the migration of sand during a hydraulic fracturing operation or a sand control operation. The presence of the surface modifying treatment agent on the surface of the solid particulate further enhances the crush resistance of the solid particulate.

This application claims the benefit of U.S. patent application Ser. No.61/880,841, filed on Sep. 20, 2013; U.S. patent application Ser. No.61/880,758, filed on Sep. 20, 2013; U.S. patent application Ser. No.61/981,051, filed on Apr. 17, 2014 and U.S. patent application Ser. No.61/989,267, filed on May 6, 2014; all of which are herein incorporatedby reference.

FIELD OF THE DISCLOSURE

The disclosure relates to a well treating composite and to methods forusing the composite. The composite is made of a solid particulate and asurface modifying treatment agent having an anchor and at least onehydrophobic tail. The hydrophobic tail is attached to the solidparticulate through the anchor.

BACKGROUND OF THE DISCLOSURE

Stimulation procedures often require the use of solid particulateshaving high compressive strength. In hydraulic fracturing, suchparticulates must further be capable of enhancing the production offluids and natural gas from low permeability formations.

In a typical hydraulic fracturing treatment, a treatment fluidcontaining a solid particulate or proppant is injected into the wellboreat high pressures. Once natural reservoir pressures are exceeded, thefluid induces fractures in the formation and proppant is deposited inthe fracture where it remains after the treatment is completed. Theproppant serves to hold the fracture open, thereby enhancing the abilityof fluids to migrate from the formation to the wellbore. Becausefractured well productivity depends on the ability of a fracture toconduct fluids from a formation to a wellbore, fracture conductivity isan important parameter in determining the degree of success of ahydraulic fracturing treatment.

Since the degree of stimulation afforded by the fracture treatment isdependent upon the propped width, it is important that the proppantexhibit resistance to crushing from the high stresses in the well. Whenthe proppant is unable to withstand closure stresses imposed by theformation, the solid particulates are compressed together in such a waythat they crush and fines and/or dust are generated. Generated finesand/or dust from the proppant plug pore throats in the reservoir matrix,thereby reducing reservoir permeability.

Improvements have been continuously sought to control and prevent thecrushing of proppants at in-situ reservoir conditions. For instance,resin-coated proppant materials have been designed to help form aconsolidated and permeable fracture pack when placed in the formationwherein the resin coating enhances the crush resistance of the proppant.

It is further necessary, when producing oil and/or gas from anunconsolidated subterranean formation, to prevent sand grains and/orother formation fines from migrating into the wellbore and beingproduced from the well. The creation and/or mobilization of reservoirfines during fracturing and production has also been instrumental inreducing fracture conductivity and reducing reservoir permeability dueto plugging of pore throats by the fines.

A common method to control sand migration is gravel packing which isdesigned to prevent the production of formation sand and reducemigration of unconsolidated formation particulates into the wellbore.Typically, gravel pack operations involve placing a gravel pack screenin the wellbore. A carrier fluid carrying the solid particulates or“gravel” leaks off into the subterranean zone and/or is returned to thesurface while the particulates are left in the zone and are packed inthe surrounding annulus between the screen and the wellbore. Theparticulates operate to trap, and thus prevent the further migration of,formation sand and fines which would otherwise be produced along withthe formation fluid. Like proppants, sand control particulates mustexhibit high strength and be capable of functioning in low permeabilityformations.

In some situations the processes of hydraulic fracturing and gravelpacking are combined into a single treatment to provide stimulatedproduction and reduce formation sand production. Such treatments areoften referred to as “frac pack” operations. In some cases, thetreatments are completed with a gravel pack screen assembly in place andthe hydraulic fracturing fluid is pumped through the annular spacebetween the casing and screen. In such a situation, the hydraulicfracturing treatment usually ends in a screen out condition creating anannular gravel pack between the screen and casing. This allows both thehydraulic fracturing treatment and gravel pack to be placed in a singleoperation.

Coated and/or uncoated particulates have further been used in gravelpacking to minimize the migration of generated fines and/or dust. Whilethe use of resin coated proppants has been successful in minimizing thegeneration of fines during hydraulic fracturing and fine migrationduring gravel packing, such materials are known to often erode oil andgas production equipment. There is an ongoing need to developparticulates exhibiting crush resistance that can be used as proppantsand gravel for minimizing fines generation and fines migration, reduceproppant pack and gravel pack damage, and which are less eroding to oiland gas production equipment while exhibiting tolerance to in-situstress conditions.

In addition to concerns arising from the creation of fines and dustdownhole, the release of dust during transport of proppant and sandcontrol particulates has come recently under close scrutiny as healthconcerns of field workers and those within residential areas within thevicinity of on-shore fracturing has risen. There has not been anacceptable method developed to date specifically designed to reduce therelease of dust from proppants and sand control particulates. Whileresin coating of frac sand has been noted to decrease dust production,the addition of a resin coating doubles the cost of frac sand. Inaddition, the chemicals used to make the resins are not environmentallyfriendly. Lastly, the application of resin coating to frac sand requiresthe sand to be heated either by electricity or the burning of naturalgas, both of which are costly. Alternative methods for reducing thegeneration of dust from particulates as well as controlling themigration of particulates in producing formations have thus been sought.

Further, alternative materials have been sought for use in selectivesimulation operations. Typically, a subterranean formation penetrated bya well has a plurality of distinct zones or formations of interest.During production of fluids from the well, it usually is desirable toestablish communication with only the zone or formations of interestsuch that stimulation treatments do not inadvertently flow into anon-productive zone or a zone of diminished interest. Selectivestimulation (such as by hydraulic fracturing and acid stimulation)becomes pronounced as the life of the well declines and productivity ofthe well decreases.

Typically, selective stimulation entails perforating the zone and/orformation with a perforating gun placed adjacent to the zone and/orformation of interest. The procedure is repeated until all of the zonesand/or formations of interest have been perforated. The perforating gunis then retrieved to the surface by means of a wireline. When fracturingis desired, the fracturing fluid is pumped into the well under pressureexceeding the pressure at which the zone and/or formations wouldfracture. In order to prevent the fracturing fluid from flowing intozones having greater porosity and/or lower pressure, a mechanicaldevice, such as a straddle packer, or plug or sand fill may be set inthe well between a fractured zone and the zone to be fractured toisolate the stimulated zone from further contact with the fracturingfluid. This procedure is then repeated until all of the zones ofinterest are perforated and fractured. Once the completion operation isfinished, each plug is drilled out of or otherwise removed from the wellto permit fluid to be produced to the surface.

Recently, methods and assemblies have been developed for effectuatingzonal isolation between intervals of the wellbore that do not depend onthe removal of perforating equipment in and out of the well. Forinstance, attention has been focused on the use of isolation assemblieswhich allow for selected treatment of productive (or previouslyproducing intervals) in multiple interval wellbores. Zonal isolationassemblies are expensive and alternatives have been sought.

Focus has been centered recently on the use of swellable elastomericmaterials as packers and isolation profilers. However, the use ofswellable elastomeric polymers in wells is often limited due to evasiveorganic and inorganic chemicals, temperatures, pressures and othersubterranean environmental factors that decrease the life and thereliability of the elastomer. Such factors also present problems toother components used in the recovery of hydrocarbons from wells. Forinstance, enzymes commonly used as breakers in fracturing fluids aretypically inactivated at high temperatures. Their use at elevatedtemperatures, for instance, at temperatures greater than 150° F., causesthem to denature and lose activity.

Ineffective fracturing of a formation may also result from the loss offriction between tubular and other metallic substrates within the well.Friction reduction between treatment fluids and surfaces contacted bythe fluid has also presented ongoing issues. In many instances, thetypes of viscosifying agents which may be used in fracturing fluids islimited since friction reduction equates to a faster reduction inviscosity of the viscosifying agent upon contact with hydrocarbons.Alternatives have been sought for addressing friction reduction atin-situ downhole conditions.

Resources have also been spent on both chemical and physical techniquesfor effectively reducing frictional drag created during the flow ofhydrocarbons within a hydrocarbon producing reservoir. Alternatives forreducing friction have focused on drag reduction agents. Typically,friction reduction agents are large polymers with long chains which tendto build non-Newtonian gel structures. Drag reducing gels areshear-sensitive and often require specialized injection equipment (suchas pressurized delivery systems). Further, since friction reductionagents are typically highly viscous, usually no more than 10 weightpercent of polymeric friction reduction agents are present in thecarrier fluid. Some attention has been focused on the use of slurries ordispersions of polymers to form free-flowing and pumpable mixtures inliquid media. However, such polymers often agglomerate over time, thusmaking it very difficult for them to be placed in hydrocarbon liquidswhere reduced drag is needed. Further alternatives for lowering thefrictional drag of fluids within a well have been sought in order toenhance the productivity of hydrocarbons from the well.

In addition, alternatives have been sought for controlling or inhibitingthe formation and/or precipitation of scales, paraffins and asphaltenesduring the production of hydrocarbons in subterranean formations. Whilewell treatment agents have been successfully employed to control and/orinhibit the formation of scales, paraffins and asphaltenes, such agentsare typically mixed on the fly with other components, such as proppantand sand control particulates. Alternative means of controlling theformation and/or inhibition of scales, paraffins and asphaltenes whichsimplify preparation of well treatment fluids on site are desired.

It should be understood that the above-described discussion is providedfor illustrative purposes only and is not intended to limit the scope orsubject matter of the appended claims or those of any related patentapplication or patent. Thus, none of the appended claims or claims ofany related application or patent should be limited by the abovediscussion or construed to address, include or exclude each or any ofthe above-cited features or disadvantages merely because of the mentionthereof herein.

SUMMARY OF THE DISCLOSURE

In an embodiment of the disclosure, a composite is provided for treatinga well. The composite comprises a surface modifying treatment agent atleast partially coated onto a solid particulate. The surface modifyingtreatment agent has a metallic anchor and a hydrophobic tail. Thehydrophobic tail is an organo-silicon material, a fluorinatedhydrocarbon or both a hydrophobic organo-silicon material and afluorinated hydrocarbon. The metallic anchor of the surface modifyingtreatment agent is attached to the solid particulate.

In another embodiment of the disclosure, a composite is provided fortreating a well. The composite contains a solid particulate and asurface modifying treatment agent. The surface modifying treatment agentis composed of a metallic anchor and at least one hydrophobic tailattached to the metal of the metallic anchor. The metallic anchor isattached to the solid particulate.

In another embodiment of the disclosure, a composite is provided for usein a well treating operation such as hydraulic fracturing or a sandcontrol operation. The composite has a surface modifying treatment agentwhich is attached to at least a portion of the surface of a solidparticulate. The surface modifying treatment has a hydrophobic tail andan anchor site. The anchor links the hydrophobic tail to the solidparticulate.

In another embodiment, a composite for treating a wellbore is providedwhich comprises (i) a solid particulate capable of withstanding stressesgreater than about 1500 psi at a temperature greater than 150° F. and(ii) a surface modifying treatment agent attached to at least a portionof the surface of the solid particulate. The surface modifying treatmentagent comprises an anchor and a hydrophobic tail. The hydrophobic tailis indirectly attached to the solid particulate through the anchor.

In another embodiment of the disclosure, a composite is provided fortreating a wellbore, wherein the composite comprises a surface modifyingtreatment agent and a solid particulate capable of withstanding stressesgreater than about 1500 psi at a temperature greater than 150° F. Thesurface modifying treatment agent comprises a metallic anchor and ahydrophobic tail. The hydrophobic tail is attached to the metal of themetallic anchor, the metallic anchor being attached to the solidparticulate.

In another embodiment, a composite for treating a wellbore is disclosed,wherein the composite comprises a solid particulate and a surfacemodifying treatment agent of the formula X-M, wherein M is a metalcontaining organic ligand and X is a hydrophobic tail. The surfacemodifying treatment agent is attached to the solid particulate by themetal containing organic ligand.

In another embodiment, a composite for treating a wellbore is providedwherein the composite comprises (i) a solid particulate and (ii) asurface modifying treatment agent comprising the product of a metalcontaining organic ligand and an organo-silicon containing hydrophobicmaterial. The metal of the metal containing organic ligand is a Group 3,4, 5 or 6 metal and the organic ligand is an alkoxide, halide, ketoacid, amine or acrylate.

In another embodiment, a method for treating a well penetrating asubterranean formation is provided. In this method, a composite of asolid particulate and a surface modifying treatment agent is introducedinto the well. The surface modifying treatment agent has a metallicanchor and a hydrophobic tail. At least a portion of the surface of thesolid particulate is coated with the surface modifying treatment agent.The hydrophobic tail is an organo-silicon material, a fluorinatedhydrocarbon or both a hydrophobic organo-silicon material and afluorinated hydrocarbon. The metallic anchor of the surface modifyingtreatment agent is attached to the solid particulate.

In another embodiment, a method for treating a well penetrating asubterranean formation is provided. In this method, a composite having asurface modifying treatment agent and a hydrophobic tail is formedin-situ within the well. In this embodiment a solid particulate may beintroduced into the well. A surface modifying treatment agent is thenintroduced. The surface modifying treatment agent has a metallic anchorand a hydrophobic tail. The metallic anchor of the surface modifyingtreatment agent attaches to at least a portion of the surface of thesolid particulate. The hydrophobic tail of the surface modifyingtreatment agent is an organo-silicon material, a fluorinated hydrocarbonor both a hydrophobic organo-silicon material and a fluorinatedhydrocarbon.

In another embodiment of the disclosure, a method of treating a wellpenetrating a subterranean formation is provided wherein a composite isintroduced into the well. The composite has a solid particulate and asurface modifying treatment agent on at least a portion of the surfaceof the solid particulate. The surface modifying treatment agent has ametallic anchor and at least one hydrophobic tail attached to the metalof the metallic anchor. The metallic anchor is attached to the solidparticulate.

In another embodiment, a method for treating a well penetrating asubterranean formation is provided. In this method, a solid particulateis introduced into the well. A surface modifying treatment agent is thenpumped into the well. The surface modifying treatment agent contains ametallic anchor and a hydrophobic tail. The metallic anchor of thesurface modifying treatment agent attaches to at least a portion of thesurface of the solid particulate in-situ.

In another embodiment of the disclosure, a method of reducing the amountof fines generated during a hydraulic fracturing operation or a sandcontrol operation is provided. In the method, a solid particulate ispumped into a well penetrating a subterranean formation. A surfacemodifying treatment agent is attached onto at least a portion of thesurface of the solid particulate. The surface modifying treatment has ahydrophobic tail and an anchor. The anchor secures the hydrophobic tailto the solid particulate.

In another embodiment of the disclosure, a composite of a surfacemodifying treatment agent and a solid particulate is pumped into a well.The well penetrates a formation having multiple productive zones. Thesurface modifying treatment agent has an anchor and a hydrophobic tail.The surface modifying treatment agent is attached to the solidparticulate by its anchor. The composite isolates a pre-determinedproductive zone from other zones of the well.

In another embodiment of the disclosure, a composite of a surfacemodifying treatment agent and a solid particulate is pumped into a well.The composite has an anchor and a hydrophobic tail. The surfacemodifying treatment agent is attached to the solid particulate by theanchor. The composite minimizes tubular friction pressures within thewell.

In another embodiment of the disclosure, a composite of a surfacemodifying treatment agent and a solid particulate is formed in-situ in awell. The well penetrates a formation having multiple productive zones.The composite is formed by first introducing into a well a solidparticulate. The surface modifying treatment agent is then introducedinto the well and forms a coating on at least a portion of the surfaceof the solid particulate. The surface modifying treatment agent has ananchor and a hydrophobic tail. The composite isolates a pre-determinedproductive zone from other zones of the well.

In another embodiment of the disclosure, a composite of a surfacemodifying treatment agent and a solid particulate is formed in-situ in awell. The composite has an anchor and a hydrophobic tail. The compositeis formed by first introducing into a well a solid particulate. Thesurface modifying treatment agent is then introduced into the well andforms a coating on at least a portion of the surface of the solidparticulate. The surface modifying treatment agent has an anchor and ahydrophobic tail. The composite minimizes tubular friction pressureswithin the well.

In another embodiment of the disclosure, a method for treating a wellpenetrating a subterranean formation is provided wherein a composite ispumped into the well wherein the composite comprises a solid particulateand a surface modifying treatment agent on the solid particulate. Thesurface modifying treatment agent comprises a metal linked to ahydrophobic organo-silicon material, a fluorinated hydrocarbon or toboth a hydrophobic organo-silicon material and a fluorinatedhydrocarbon. The metal is attached to the solid particulate.

In another embodiment of the disclosure, a method for treating a wellpenetrating a subterranean formation is provided wherein a composite ispumped into the well wherein the composite comprises a solid particulateand a surface modifying treatment agent on at least a portion of thesurface of the solid particulate. The surface modifying treatment agentis a reaction product of an organometallic compound having an oxygenligand and an organo-silicon containing material.

In another embodiment of the disclosure, a method for treating a wellpenetrating a subterranean formation is provided wherein a composite ispumped into the well wherein the composite comprises a solid particulateand a surface modifying treatment agent of the formula X-M, wherein M isa metal containing organic ligand and X is a hydrophobic tail.

In another embodiment of the disclosure, a method of stimulating asubterranean formation is provided. In the method, a composite is pumpedinto a well penetrating the subterranean formation at a pressure abovethe fracturing pressure of the subterranean formation. The composite maybe characterized by a solid particulate having coated onto at least aportion of its surface a surface modifying treatment agent. The surfacemodifying treatment agent contains a hydrophobic tail and an anchor forsecuring the hydrophobic tail to the surface of the solid particulate.The generation of fines or dust from the solid particulate is minimizedduring stimulation and damage to a proppant pack within the formation isminimized by the presence of the surface modifying treatment agent onthe solid particulate.

In another embodiment of the disclosure, a method of reducing thegeneration of fines and/or dust from a proppant or sand controlparticulate during a well treatment operation is provided. In thisembodiment, a composite is formed by self-assembly onto at least aportion of the surface of the proppant or sand control particulate asurface modifying treatment agent. The surface modifying treatment agentis characterized by a hydrophobic tail and an anchor for securing thehydrophobic tail to the proppant or sand control particulate. The amountof fines and/or dust generated from the proppant or sand controlparticulate is reduced by the self-assembly of the surface modifyingtreatment agent onto the proppant or sand control particulate.

In another embodiment, a method of reducing the generation of finesduring the production of hydrocarbons from a subterranean formation isprovided. In the method a proppant or sand control particulate is pumpedinto the well. The proppant or sand control particulate is coated with asurface modifying treatment characterized by a hydrophobic tail and ananchor for adhering the hydrophobic tail to the proppant or sand controlparticulate. The amount of fines generated during pumping of theproppant or sand control particulate into the well is less than theamount of fines generated during pumping of the pristine proppant orsand control particulate into the well.

In another embodiment, a method of reducing the amount of finesgenerated during pumping of a proppant or a sand control particulateinto a well is provided. In the method, at least a portion of thesurface of the proppant or sand control particulate is coated with asurface modifying treatment agent prior to pumping the proppant or sandcontrol particulate into the well. The surface modifying treatment agentcontains a hydrophobic tail and an anchor for securing the hydrophobictail to the proppant or sand control particulate. The amount of finesgenerated during pumping of the proppant or sand control particulateinto the well is less than the amount of fines generated during pumpingof a pristine proppant or sand control particulate into the well.

In another embodiment, a method of preventing the release of dust from aproppant or sand control particulate during a well treatment operationis provided. In the method, at least a portion of the surface of theproppant or sand control particulate is coated with a surface modifyingtreatment agent. The surface modifying treatment agent comprises ahydrophobic tail and an anchor for securing the hydrophobic tail to theproppant or sand control particulate. The coated proppant or coated sandcontrol particulate is then pumped into a well which penetrates ahydrocarbon producing reservoir. The amount of dust released from theproppant or sand control particulate is reduced by the presence of thesurface modifying treatment agent on the surface of the proppant or sandcontrol particulate.

In another embodiment of the disclosure, a method of increasing crushresistance of a proppant pumped into a well penetrating a subterraneanformation during a hydraulic fracturing operation is provided. In thismethod a proppant is treated with a surface modifying treatment agent.The surface modifying treatment agent is characterized by a hydrophobictail and an anchor for securing the hydrophobic tail to the surface ofthe proppant. The crush resistance of the proppant at a closure stressof 1,500 psi, API RP 5856 or API RP 60, is greater than the crushresistance of a pristine proppant at a temperature greater than 150° F.

In another embodiment of the disclosure, a method of preventing themigration of sand during a sand control operation within a well isprovided. In the method, a sand control particulate agent is pumped intoa well. At least a portion of the surface of the sand controlparticulate is treated with a surface modifying treatment comprising ahydrophobic tail and an anchor. The anchor secures the hydrophobic tailto the surface of the sand control particulate.

In another embodiment of the disclosure, a method of preventing themigration of sand during a sand control operation is provided. In themethod, a sand control particulate is pumped into a well. A surfacemodifying treatment agent comprising a hydrophobic tail and an anchor issecured to at least a portion of the surface of the sand controlparticulate in-situ through the anchor.

In another embodiment of the disclosure, a method of reducing the amountof fines generated during a hydraulic fracturing operation or a sandcontrol operation within a subterranean formation is provided. In themethod, a solid particulate is pumped into a well penetrating thesubterranean formation. A surface modifying treatment comprising ahydrophobic tail and an anchor is then secured onto at least a portionof the surface of the solid particulate in-situ through the anchor ofthe surface modifying treatment agent.

In still another embodiment of the disclosure, a method of stimulating asubterranean formation is provided wherein a fracturing fluid containinga solid particulate is pumped into a well penetrating the subterraneanformation at a pressure above the fracturing pressure of thesubterranean formation. A surface modifying treatment agent is securedin-situ onto at least a portion of the surface of the solid particulate.The surface modifying treatment agent comprises a hydrophobic tail andan anchor for securing the hydrophobic tail to the solid particulate.The generation of fines or dust from the solid particulate is minimizedand damage to a proppant pack within the formation is minimized by thepresence of the surface modifying treatment agent on the solidparticulate.

In still another embodiment of the disclosure, a method of reducing thegeneration of fines and/or dust from a proppant or sand controlparticulate during a well treatment operation is provided. In thismethod, a proppant or sand control particulate is pumped into the well.A surface modifying treatment agent comprising a hydrophobic tail and ananchor is then pumped into the well. The surface modifying treatmentagent through its anchor is secured onto at least a portion of theproppant or sand control particulate in-situ. The amount of fines and/ordust generated from the proppant or sand control particulate is reducedby the presence of the surface modifying treatment agent on the surfaceof the proppant or sand control particulate.

In a further embodiment of the disclosure, a method of preventing therelease of dust from a proppant or sand control particulate during awell treatment operation is provided. In this method, a proppant or sandcontrol particulate is pumped into a well penetrating a subterraneanformation. A surface modifying treatment agent is secured in-situ ontoat least a portion of the surface of the proppant or sand controlparticulate. The surface modifying treatment agent has a hydrophobictail and an anchor. The surface modifying treatment agent is securedonto the surface of the proppant or sand control particulate through theanchor. The amount of dust released from the proppant or sand controlparticulate during the well treatment operation is reduced by thepresence of the surface modifying treatment agent on the surface of theproppant or sand control particulate.

In still another embodiment of the disclosure, a method of increasingcrush resistance of a proppant pumped into a well penetrating asubterranean formation during a hydraulic fracturing operation isprovided. In this method, a surface modifying treatment agent comprisinga hydrophobic tail and an anchor is secured onto at least a portion ofthe surface of the proppant after the proppant is placed into the well.The surface modifying treatment agent is secured onto the surface of theproppant through its anchor. The crush resistance of the proppant at aclosure stress of 1,500 psi, AAPI 56 or API RP 60, is greater than thecrush resistance of a pristine proppant.

In another embodiment of the disclosure, a method for treating a wellpenetrating a subterranean formation is provided wherein a composite ispumped into the well wherein the composite comprises (i) a solidparticulate and (ii) a surface modifying treatment agent comprising theproduct of a metal containing organic ligand and an organo-siliconcontaining hydrophobic material. The metal of the metal containingorganic ligand is a Group 3, 4, 5 or 6 metal and the organic ligand isan alkoxide, halide, keto acid, amine or acrylate.

In another embodiment, a method of enhancing the productivity of asubterranean formation is disclosed wherein a composite is introducedinto the well. The composite comprises an elastomeric core and a surfacemodifying treatment agent at least partially coated onto the elastomericcore. The surface modifying treatment agent is comprised of a metallinked to a hydrophobic organo-silicon material, a fluorinatedhydrocarbon or to both a hydrophobic organo-silicon material and afluorinated hydrocarbon and wherein the metal is attached to theelastomeric core.

In another embodiment, a composite comprising an elastomeric core and asurface modifying treatment agent is disclosed in isolating a productivezone from other zones of the well. The composite comprises anelastomeric core and a surface modifying treatment agent at leastpartially coated onto the elastomeric core. The surface modifyingtreatment agent is comprised of a metal linked to a hydrophobicorgano-silicon material, a fluorinated hydrocarbon or to both ahydrophobic organo-silicon material and a fluorinated hydrocarbon andwherein the metal is attached to the elastomeric core.

In another embodiment, a composite comprising an elastomeric core and asurface modifying treatment agent is disclosed to enhance theeffectiveness of a breaker during a hydraulic fracturing operation. Thecomposite comprises an elastomeric core and a surface modifyingtreatment agent at least partially coated onto the elastomeric core. Thesurface modifying treatment agent has a hydrophobic tail and an anchorfor adhering the hydrophobic tail to the elastomeric core. The anchor isa metal.

In another embodiment, a composite comprising an elastomeric core and asurface modifying treatment agent is disclosed to minimize tubularfrictions pressures within a well. The composite comprises anelastomeric core and a surface modifying treatment agent at leastpartially coated onto the elastomeric core. The surface modifyingtreatment agent has a hydrophobic tail and an anchor for adhering thehydrophobic tail to the elastomeric core. The anchor is a metal.

In another embodiment of the disclosure, a method of producinghydrocarbons from an underground reservoir is provided wherein acomposite having an elastomeric core and a surface modifying treatmentagent at least partially coated onto the elastomeric core is pumped intoan underground reservoir. The surface modifying treatment agent containsa hydrophobic tail and an anchor for adhering the hydrophobic tail tothe elastomeric core. The anchor is a metal. The hydrophobic tail is notdirectly attached to elastomeric core but is only indirectly attachedthrough the anchor.

In another embodiment, a method of treating a subterranean formationpenetrated by a well is disclosed wherein a composite having anelastomeric core and a surface modifying treatment agent at leastpartially coated onto the elastomeric core is pumped into thesubterranean formation through a wellbore. The surface modifyingtreatment agent comprising, as hydrophobic tail, an organo-siliconmaterial, a fluorinated hydrocarbon or both a hydrophobic organo-siliconmaterial and a fluorinated hydrocarbon. The anchor is a metal.

Characteristics and advantages of the present disclosure described aboveand additional features and benefits will be readily apparent to thoseskilled in the art upon consideration of the following detaileddescription of various embodiments and referring to the accompanyingdrawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are part of the present specification, included todemonstrate certain aspects of various embodiments of this disclosureand referenced in the detailed description herein:

FIGS. 1 and 2 depict schematic representations of the attachment of asurface modifying treatment agent containing a metallic anchor onto thesurface of a solid particulate.

FIG. 3 illustrates retention in permeability in a synthetic corecontaining 20-40 Carbolite proppant and 80-100 mesh silica sand whenusing the surface modifying treatment agent described herein

FIG. 4 illustrates the permeability recovery in a proppant/gravel(treated and untreated) after exposing the pack to water, linear gel andthen water.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Characteristics and advantages of the present disclosure and additionalfeatures and benefits will be readily apparent to those skilled in theart upon consideration of the following detailed description ofexemplary embodiments of the present disclosure. It should be understoodthat the description herein, being of example embodiments, are notintended to limit the claims of this patent or any patent or patentapplication claiming priority hereto. On the contrary, the intention isto cover all modifications, equivalents and alternatives falling withinthe spirit and scope of the claims. Many changes may be made to theparticular embodiments and details disclosed herein without departingfrom such spirit and scope.

Certain terms are used herein and in the appended claims may refer toparticular components, process steps or well treatment operations. Asone skilled in the art will appreciate, different persons may refer to acomponent, a process step or a well treatment operation by differentnames. This document does not intend to distinguish between components,process steps or well treatment operations that differ in name but notfunction or operation. Also, the terms “including” and “comprising” areused herein and in the appended claims in an open-ended fashion, andthus should be interpreted to mean “including, but not limited to . . .. ” The term “introducing” in regards to introduction of a material orfluid into a well or subterranean formation shall include pumping orinjecting of the material or fluid into the well or formation. Further,reference herein and in the appended claims to components and aspects ina singular tense does not necessarily limit the present disclosure orappended claims to only one such component or aspect, but should beinterpreted generally to mean one or more, as may be suitable anddesirable in each particular instance.

The composite is comprised of a solid particulate and a surfacemodifying treatment agent which exhibits hydrophobicity. The surfacemodifying treatment agent may comprise a hydrophobic tail and an anchorfor attaching the hydrophobic tail to the solid particulate. [As usedherein, the terms “attaching” or “securing” shall include, but not belimited to, adhering, grafting, bonding (including covalently bonding),coating or otherwise linking the hydrophobic tail to the solidparticulate. Also, as used herein, the term “hydrophobic tail” shallrefer to the hydrophobic substituent of the surface modifying treatmentagent.] The hydrophobic nature of the tail may further alter thewettability of the surface of the solid particulate. While the tail ofthe surface modifying treatment agent exhibits hydrophobiccharacteristics, it may also exhibit oleophobic properties. The surfacemodifying treatment agent may therefore be considered to be omniphobic.

The anchor serves to connect (preferably by covalent bonding) thesurface modifying treatment agent to the surface of the solidparticulate. The hydrophobic tail attached to the anchor of the surfacemodifying treatment agent is not believed to bind to the surface of thesolid particulate. Thus, the tail of the surface modifying treatmentagent is only indirectly attached to the particulate, through theanchor.

The hydrophobicity provided the solid particulate by the surfacemodifying treatment agent may extend the lifetime of the particulatecompared to when the solid particulate is in its pristine state. [Theterm “pristine” as used herein refers to a solid particulate not coatedwith a surface modifying treatment agent. When comparing a pristinesolid particulate to a solid particulate having an attached surfacemodifying treatment agent, it is understood that the solid particulateof the composite is the same particulate as the (uncoated or) pristineparticulate.]

The composite generally has the ability to withstand greater than 20 psistress at a temperature greater than 150° F. without breaking. When usedin a hydraulic fracturing operation, the composite typically has theability to withstand greater than about 1500 psi at a temperaturegreater than 150° F., API RP 56 or API RP 60, without decomposing. Theparticulates may deform with stress and yet are sufficiently strong tobe used on their own at high pressures in excess of 4,000 psi. Thecomposites prevent sand grains and/or other formation fines frommigrating into the wellbore.

When used in a hydraulic fracturing operation, the solid particulate ofthe composite may be a proppant. When used in a sand control operation,the surface modifying treatment agent may be a sand control particulate.

The surface modifying treatment agent may completely surround the solidparticulate. Alternatively, the surface modifying treatment agent may beapplied only to a portion of the solid particulate. In a preferredembodiment, the surface modifying treatment agent may be applied ontofrom about 10 to 100% of the surface area of the solid particulate andpreferably about 75% of the surface area of the solid particulate. In amost preferred embodiment, the surface modifying treatment agent coversall of the surface area of the solid particulate. The thickness of thesurface modifying treatment agent on the solid particulate is typicallybetween from about 2 to about 40 nm.

Typically, the composite is prepared prior to being pumped into the welland/or formation. However, the surface modifying treatment agent may bepumped into the well and the solid particulates may then be coatedin-situ onto the solid particulate within the well. Thus, an embodimentof the disclosure includes the method of covalently bonding or attachingthe hydrophobic, oleophobic or omniphobic tail onto proppant or gravelpack particulates under in-situ conditions. For instance, a surfacemodifying treatment agent may be remedially pumped into the well after aproppant pack is formed within the well and/or formation. In suchinstances, the surface modifying treatment agent is secured ontoproppant particulates defining a proppant pack in-situ.

When the composite is formed in-situ, the surface modifying treatmentagent and the solid particulate may be pumped into the wellbore usingthe same (as well as a different) treatment fluid.

The solid particulate of the composite may be elastomeric. Theelastomers may form an elastomeric core onto which is coated the surfacemodifying treatment agent. Elastomers useful in the composites disclosedherein include natural rubber and man-made substances emulating naturalrubber which stretch under tension, exhibit a high tensile strength,retract rapidly, and substantially recover their original dimensions.The term “elastomers” as used herein includes thermoplastic elastomersand non-thermoplastic elastomers. The term includes blends (physicalmixtures) of elastomers, as well as copolymers, terpolymers, andmulti-polymers. Included as suitable elastomers areethylene-propylene-diene polymer (EPDM), nitrile rubbers such ascopolymers of butadiene and acrylonitrite, carboxylated acrylonitrilebutadiene copolymers, polyvinylchloride-nitrile butadiene blends,chlorinated polyethylene, chlorinated sulfonate polyethylene, aliphaticpolyesters with chlorinated side chains (such as epichlorohydrinhomopolymer, epichlorohydrin copolymer, and epichlorohydrin terpolymer,polyacrylate rubbers such as ethylene-acrylate copolymer,ethylene-acrylate terpolymers, elastomers of ethylene and propylene,sometimes with a third monomer, such as ethylene-propylene copolymer(EPM), ethylene vinyl acetate copolymers, fluorocarbon polymers,copolymers of poly(vinylidene fluoride) and hexafluoropropylene,terpolymers of poly(vinylidene fluoride), hexafluoropropylene, andtetrafluoroethylene, terpolymers of poly(vinylidene fluoride), polyvinylmethyl ether and tetrafluoroethylene, terpolymers of poly(vinylidenefluoride), hexafluoropropylene, and tetrafluoroethylene, terpolymers ofpoly(vinylidene fluoride), tetrafluoroethylene, and propylene,perfluoroelastomers such as tetrafluoroethylene perfluoroelastomers,highly fluorinated elastomers, butadiene rubber, polychloroprenerubber), polyisoprene rubber, polynorbornenes, polysulfide rubbers,polyurethanes, silicone rubbers, vinyl silicone rubbers, fluoromethylsilicone rubber, fluorovinyl silicone rubbers, phenylmethyl siliconerubbers, styrene-butadiene rubbers, copolymers of isobutylene andisoprene or butyl rubbers, brominated copolymers of isobutylene andisoprene and chlorinated copolymers of isobutylene and isoprene.

Suitable examples of fluoroelastomers are copolymers of vinylidenefluoride and hexafluoropropylene and terpolymers of vinylidene fluoride,hexafluoropropylene and tetrafluoroethylene. The fluoroelastomerssuitable may comprise one or more vinylidene fluoride unit, one or morehexafluoropropylene units, one or more tetrafluoroethylene units, one ormore chlorotrifluoroethylene units, and/or one or more perfluoro(alkylvinyl ether) units such as perfluoro(methyl vinyl ether),perfluoro(ethyl vinyl ether), and perfluoro(propyl vinyl ether). Theseelastomers can be homopolymers or copolymers. Particularly suitable arefluoroelastomers containing vinylidene fluoride units,hexafluoropropylene units, and, optionally, tetrafluoroethylene unitsand fluoroelastomers containing vinylidene fluoride units,perfluoroalkyl perfluorovinyl ether units, and tetrafluoroethylene unitsas well as copolymers of vinylidene fluoride and hexafluoropropyleneunits.

Commercially available thermoplastic elastomers include segmentedpolyester thermoplastic elastomers, segmented polyurethane thermoplasticelastomers, segmented polyamide thermoplastic elastomers, blends ofthermoplastic elastomers and thermoplastic polymers, and ionomericthermoplastic elastomers.

Other exemplary materials for the solid particulate of the composite foruse in the disclosure include ceramics, sand, bauxite, alumina,minerals, nut shells, gravel, glass, resinous particles, polymericparticles, as well as combinations thereof.

Examples of ceramics include oxide-based ceramics, nitride-basedceramics, carbide-based ceramics, boride-based ceramics, silicide-basedceramics, or a combination thereof. In an embodiment, the oxide-basedceramic is silica (SiO₂), titania (TiO₂), aluminum oxide, boron oxide,potassium oxide, zirconium oxide, magnesium oxide, calcium oxide,lithium oxide, phosphorous oxide, and/or titanium oxide, or acombination thereof. The oxide-based ceramic, nitride-based ceramic,carbide-based ceramic, boride-based ceramic, or silicide-based ceramiccontain a nonmetal (e.g., oxygen, nitrogen, boron, carbon, or silicon,and the like), metal (e.g., aluminum, lead, bismuth, and the like),transition metal (e.g., niobium, tungsten, titanium, zirconium, hafnium,yttrium, and the like), alkali metal (e.g., lithium, potassium, and thelike), alkaline earth metal (e.g., calcium, magnesium, strontium, andthe like), rare earth (e.g., lanthanum, cerium, and the like), orhalogen (e.g., fluorine, chlorine, and the like). Exemplary ceramicsinclude zirconia, stabilized zirconia, mullite, zirconia toughenedalumina, spinel, aluminosilicates (e.g., mullite, cordierite),perovskite, silicon carbide, silicon nitride, titanium carbide, titaniumnitride, aluminum carbide, aluminum nitride, zirconium carbide,zirconium nitride, iron carbide, aluminum oxynitride, silicon aluminumoxynitride, aluminum titanate, tungsten carbide, tungsten nitride,steatite, and the like, or a combination thereof.

Examples of suitable sands for the solid particulate include, but arenot limited to, Arizona sand, Wisconsin sand, Badger sand, Brady sand,and Ottawa sand. In an embodiment, the solid particulate is made of amineral such as bauxite and is sintered to obtain a hard material. In anembodiment, the bauxite or sintered bauxite has a relatively highpermeability such as the bauxite material disclosed in U.S. Pat. No.4,713,203, the content of which is incorporated by reference herein inits entirety.

In another embodiment, the solid particulate is a relatively lightweightor substantially neutrally buoyant particulate material or a mixturethereof. Such materials may be chipped, ground, crushed, or otherwiseprocessed. By “relatively lightweight” it is meant that the solidparticulate has an apparent specific gravity (ASG) which is less than orequal to 2.45, including those ultra lightweight materials having an ASGless than or equal to 2.25, more preferably less than or equal to 2.0,even more preferably less than or equal to 1.75, most preferably lessthan or equal to 1.25 and often less than or equal to 1.05.

Naturally occurring solid particulates include nut shells such aswalnut, coconut, pecan, almond, ivory nut, brazil nut, and the like;seed shells of fruits such as plum, olive, peach, cherry, apricot, andthe like; seed shells of other plants such as maize (e.g., corn cobs orcorn kernels); wood materials such as those derived from oak, hickory,walnut, poplar, mahogany, and the like. Such materials are particlesformed by crushing, grinding, cutting, chipping, and the like.

Suitable relatively lightweight solid particulates are those disclosedin U.S. Pat. Nos. 6,364,018, 6,330,916 and 6,059,034, all of which areherein incorporated by reference.

Other solid particulates for use herein include resin coated plastics,resin coated ceramics or synthetic organic particle such as beads orpellets of nylon, ceramics, polystyrene, polystyrene divinyl benzene orpolyethylene terephthalate such as those set forth in U.S. Pat. No.7,931,087, herein incorporated by reference.

The term “solid particulate” as used herein includes coated particulatesas well as non-coated particulates. In an embodiment, the solidparticulate may be treated with a coating (prior to application of thesurface modifying treatment agent). The coating typically is notfluorinated and is not a derivative of a phosphorus containing acid. Forinstance, the solid particulate may be a porous ceramic having acoating, such as those set forth in U.S. Pat. No. 7,426,961, hereinincorporated by reference.

In an embodiment, any of the solid particulates disclosed herein may becoated, e.g., with a resin, prior to application of the surfacemodifying treatment agent. In some instances, the coating may impartresistance to the solid particulate and thus minimize defragmentation ofthe solid particulate during downhole operations using the compositedisclosed herein. Such coatings include cured, partially cured, oruncured coatings of, e.g., a thermoset or thermoplastic resin.

The coating of the solid particulate may be an organic compound thatincludes epoxy, phenolic, polyurethane, polycarbodiimide, polyamide,polyamide imide, furan resins, or a combination thereof. The phenolicresin is, e.g., a phenol formaldehyde resin obtained by the reaction ofphenol, bisphenol, or derivatives thereof with formaldehyde. Exemplarythermoplastics include polyethylene, acrylonitrile-butadiene styrene,polystyrene, polyvinyl chloride, fluoroplastics, polysulfide,polypropylene, styrene acrylonitrile, nylon, and phenylene oxide.Exemplary thermosets include epoxy, phenolic (a true thermosetting resinsuch as resole or a thermoplastic resin that is rendered thermosettingby a hardening agent), polyester resin, polyurethanes, epoxy-modifiedphenolic resin, and derivatives thereof.

In another embodiment, the solid particulate, prior to application ofthe surface modifying treatment agent, is a resin coated plastic, resincoated ceramic proppant.

In an embodiment, the coating of the solid particulate is a crosslinkedresin. The crosslinked coating typically provides crush strength, orresistance for the solid particulates.

Preferred solid particulates are those which have groups on theirsurface that are reactive with functional groups associated with theanchor. For instance, where the surface modifying treatment agentcontains a metallic anchor, the surface modifying treatment agent may bebound to the surface of the particulate by binding the metal of themetallic anchor to the surface. The surface may contain an oxide ofsilica or aluminum or have another reactive site for interaction withthe anchor of the surface modifying treatment agent. For instance, theparticulate may be silica sand or a ceramic.

The particle size of the solid particulates may be selected based onanticipated downhole conditions. In this regard, larger particle sizesmay be more desirable in situations where a relatively lower strengthparticulate material is employed. The solid particulates typically havea size ranging from about 4 mesh to about 100 mesh, alternatively fromabout 20 mesh to about 40 mesh.

The surface modifying treatment agent as disclosed herein is stable atin-situ temperature and pressure conditions within the well. The surfacemodifying treatment agent further enhances the lifetime of the solidparticulate.

In a preferred embodiment, the anchor comprises a metal and thehydrophobic tail comprises an organo-silicon material, a fluorinatedhydrocarbon or both an organo-silicon material and a fluorinatedhydrocarbon.

The anchor of the surface modifying treatment agent may be a metal andpreferably is Group 3, 4, 5, or 6 metal. In a preferred embodiment, themetal is a Group 4 metal, such as Ti, Zr or Hf, a Group 5 metal, such asTa or Nb, a Group 6 metal, such as W, or a metal of the lanthanideseries, such as La.

While not being bound to any theory, it is believed that the metal ofthe surface modifying treatment agent is the anchor and covalently bindsto the surface of the solid particulate. Examples are set forth in FIG.1 and FIG. 2 where J represents the hydrophobic tail and Z representsthe metal of the anchor. In FIG. 1, the surface of the solid particulatecontains a free —OH which may, for example, be attached to an aluminumatom or a silicon atom. As illustrated, the metal of the surfacemodifying treatment agent may bind to the oxygen atom of the silicon-oxoor the aluminum-oxo linkage of the substrate by reaction with the —OHgroup. In FIG. 2, the surface of the solid particulate is shown ascontaining a silicon-oxo group without a free —OH. The mechanism ofreaction of the surface modifying treatment agent is illustrated asbeing different from that set forth in FIG. 1. The hydrophobic tail isnot believed to bind to the solid particulate per se. Thus, thehydrophobic tail of the surface modifying treatment agent is onlyindirectly attached to the solid particulate through the attachmentsite.

In an embodiment, the organo-silicon containing material may be asilane, polysiloxane or a polysilazane.

Examples of organo-silicon containing materials are those having theformula R¹ _(4-x)SiA_(x) or (R¹ ₃Si)_(y)B as well asorgano(poly)siloxanes and organo(poly)silazanes containing units of theformula:

where R¹ may be the same or different and is a hydrocarbon radicalcontaining from 1 to 100, such as 1 to 20 carbon atoms and 1 to 12,preferably 1 to 6 carbon atoms and R³ may be hydrogen or a hydrocarbonor substituted hydrocarbon having 1 to 12, preferably 1 to 6 carbonatoms. In addition, R¹ may be a substituted, hydrocarbon radical such ashalo, particularly a fluoro-substituted hydrocarbon radical. Theorgano(poly)siloxane may further contain additional units of theformula: R⁵ ₂SiO₂ where R⁵ is a halogen such as a chloro or fluorosubstituent.

In an embodiment, the organo-silicon containing compound may be anorgano(poly)siloxane or organo(poly)silazane of a number averagemolecular weight of at least 400, usually between 1000 and 5,000,000.

The substituent A in R¹ _(4-x)SiA_(x) may be hydrogen, a halogen such aschloride, OH, OR² or

wherein B in the above structural formula may be NR³ _(3-y), R² ahydrocarbon or substituted hydrocarbon radical containing from 1 to 12,typically 1 to 4 carbon atoms. R³ is hydrogen or has the same meaning asR¹. x is 1, 2 or 3, y is 1 or 2.

Preferably, R¹ is a fluoro-substituted hydrocarbon. Preferred are suchfluoro-substituted hydrocarbons are those of the structure:

where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6; R² is alkylcontaining from 1 to 4 carbon atoms and p is 0 to 18. Also,fluoro-substituted hydrocarbons may be of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 6, y is F orC_(n)F_(2n); b is at least 1, such as 2 to 10; m is 0 to 6 and p is 0 to18.

Preferred organo-silicon materials include halogenated siloxanes,halogenated alkoxysiloxanes such as perfluoroalkoxysiloxane (PFOSi),alkoxy halogenated alkoxysilanes, such as alkoxy-perfluoroalkoxysilane;alkoxyacetylacetonate halogenated polysiloxanes, such asalkoxyacetylacetonate-perfluoroalkoxysiloxane, alkoxy-alkylsilylhalides;polyalkylsiloxanes, such as polydimethylsiloxanes, andalkoxyacetylacetonate-polyalkylsiloxanes, such as alkoxyacetylacetonate(acac) polydimethylsiloxanes. Exemplary surface modifying treatmentagents include tantalum halide-perfluoroalkoxysiloxane, such asTaCl₅:PFOSi; tantalum alkoxy-perfluoroalkoxysilane; tantalumalkoxyacetylacetonate-perfluoroalkoxysiloxane, like Ta(EtO)₄acac:PFOSi;tantalum alkoxy-alkylsilylhalide; tantalum halide-polyalkylsiloxane,like TaCl₅:PDMS; niobium alkoxide-perfluoroalkoxysiloxane, such asNb(EtO)₅:PFOSi and Ta(EtO)₅:PFOSi; titaniumalkoxide-perfluoroalkoxysiloxane, like Ti(n-BuO)₄:PFOSi; zirconiumalkoxide-perfluoroalkoxysiloxane; lanthanumalkoxide-perfluoroalkoxysilane, like La(iPrO)₃:PFOSi; tungstenchloride-perfluoroalkoxysiloxane, like WCl₆:PFOSi; tantalumalkoxide-polyalkylsiloxane, like Ta(EtO)₅:PDMS; and tantalumalkoxyacetylacetonate-polyalkylsiloxane, like Ta(EtO)₄acac:PDMS.

In an embodiment, the fluorinated hydrocarbon is R_(f)—(CH₂)_(p)—X whereR_(f) is a perfluorinated hydrocarbon group including an oxygensubstituted hydrocarbon group, such as a perfluorinated alkyl group or aperfluorinated alkylene ether group and p is 0 to 18, preferably 0-4,and X is a polar group such as a is carboxyl, like of the structure—(C═O)—OR; and R is hydrogen, perfluoroalkyl, alkyl or substituted alkylcontaining from 1 to 50 carbon atoms.

Examples of perfluoroalkyl groups are those of the structureF—(CFY—CF₂)_(m) where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1to 6.

Examples of perfluoroalkylene ether groups are those of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 6, Y is F orC_(n)F_(2n); b is 2 to 20, m is 0 to 6, and p is 0 to 18, preferably 2to 4 and more preferably 2.

Preferred fluorinated materials are esters of perfluorinated alcoholssuch as the alcohols of the structure F—(CFY—CF₂)_(m)—CH₂—CH₂—OH where Yis F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6.

Further preferred as fluorinated hydrocarbons are perfluorinatedhydrocarbons of the structure R_(f)—(CH₂)_(p)—X where R_(f) is aperfluoroalkylene ether group or a perfluorinated alkyl group such asthose described above, p is an integer of from 0 to 18, preferably 0 to4, and X is a carboxyl group, preferably a carboxylic ester groupcontaining from 1 to 50, preferably from 2 to 20 carbon atoms in thealkyl group that is associated with the ester linkage.

Further preferred as fluorinated hydrocarbons are perfluorinatedhydrocarbons of the structure R_(f)—(CH₂)_(p)—Z where R_(f) and p are asdefined above, preferably R_(f) is a perfluoroalkylene ether group suchas those described above, and p is from 2 to 4, and Z is a phosphorusacid group. Examples of phosphorus acid groups are:

where R″ is a hydrocarbon or substituted hydrocarbon radical having upto 200, such as 1 to 30 and 6 to 20 carbons, R″ can also include theperfluoroalkyl groups mentioned above, and R′ is H, a metal such aspotassium or sodium or an amine or an aliphatic radical, for example,alkyl including substituted alkyl having 1 to 50 carbons, preferablylower alkyl having 1 to 4 carbons such as methyl or ethyl, or arylincluding substituted aryl having 6 to 50 carbons.

Preferably, the phosphorus acid is of formula II where R and R′ are H.

The surface modifying treatment agent may be represented by the formulaX-M, wherein M is the metal containing organic ligand and X is thehydrophobic tail represented by the organo-silicon containing material,the fluorinated hydrocarbon or a combination of organo-siliconcontaining material and fluorinated hydrocarbon. The composite may beformed by reacting M with a reactive group, such as a silicon atom or analuminum atom, on the surface of the particulate.

The tail of the surface modifying treatment agent may be aligned suchthat the hydrophobicity character of the treatment agent is impartedaway from the anchor. Water and thus aqueous fluids within the well mayeasily slide across the surface of the particulate carrying hydrocarbonswith it as lateral adhesion of the fluid is reduced.

In a preferred embodiment, the tail may self-align to the surface of thesolid particulate such that the hydrophobic tail is opposite to thesurface. Thus, during a well treatment operation, the tail of thesurface modifying treatment agent may align itself such that hydrophobicgroup of the surface modifying treatment agent is imparted away from thesurface of the proppant or gravel pack.

In an embodiment, the tail of the surface modifying treatment agentself-aligns onto the surface of the particulate to form a multi-layerassembly. The formation of one or more layers of surface modifyingtreatment agents onto the surface of the particulate is believed tooccur by chemical binding-induced spontaneous organization of the tail.

The surface modifying treatment agent may be formed by reacting a metalcontaining organic ligand, such as a derivatized alkoxide, with anorgano-silicon containing material and/or fluorinated hydrocarbon group.The metal of the metal containing organic ligand may be covalentlybonded to the organosilicon compound to form the anchor and thehydrophobic tail.

The metal containing organic ligand may be formed by reacting a metalcompound, such as a metal halide, like TaCl₅, with an oxygen containingligand. Depending upon the position of the transition metal on thePeriodic Chart, the metal containing organic ligand may have from two tosix organic ligand groups.

In an embodiment, the ligand of the metal containing organic ligandcontains an alkoxide or ester. Suitable organometallic derivativesinclude metal derivatives of C₁ to C₁₈ alkoxides, preferably alkoxidescontaining from 2 to 8 carbon atoms such as ethoxide, propoxide,isopropoxide, butoxide, isobutoxide and tertiary butoxide. For instance,the metal containing organic ligand may be a transition metaltetra-alkoxide, such as zirconium tetra tert-butoxide.

The alkoxides may be in the form of simple esters and polymeric forms ofthe alkoxylates and esters as well as various chelates and complexes.For example, with the metal Ta, the simple esters could be Ta(OR)₅ whereR is C₁ to C₁₈ alkyl. Polymeric esters may be obtained by condensationof an alkyl ester and can have the structure RO—[Ta(OR)₃—O—]_(x)—R whereR is defined above and x is a positive integer.

Further, the organometallic compound can include, for instance, when themetal is titanium or zirconium:

(a) alkoxylates having the general formula M(OR)₄, wherein M is selectedfrom Ti and Zr and R is C₁₋₁₈ alkyl;

(b) polymeric alkyl titanates and zirconates obtainable by condensationof the alkoxylates of (a), i.e., partially hydrolyzed alkoxylates of thegeneral formula RO[-M(OR)₂O—]_(X-1)R, wherein M and R are as above and xis a positive integer;

(c) titanium chelates, derived from ortho titanic acid andpolyfunctional alcohols containing one or more additional hydroxyl,halo, keto, carboxyl or amino groups capable of donating electrons totitanium. Examples of these chelates are those having the generalformula Ti(O)_(a)(OH)_(b)(OR′)_(c)(XY)_(d), wherein a=4−b−c−d;b=4−a−c−d; c=4−a−b−d; d=4−a−b−c; R′ is H, R as above or X—Y, wherein Xis an electron donating group such as oxygen or nitrogen and Y is analiphatic radical having a two or three carbon atom chain such as:

-   -   (i) —CH₂CH₂—, e.g., of ethanolamine, diethanolamine and        triethanolamine,

-   -   (ii) lactic acid,

-   -   (iii) acetylacetone enol form, and

-   -   (iv) 1,3-octyleneglycol,

(d) titanium acrylates having the general formula Ti(OCOR)_(4-n)(OR)_(n)wherein R is C₁₋₁₈ alkyl as above and n is an integer of from 1 to 3,and polymeric forms thereof, or

(e) mixtures thereof.

Acetyl acetonates, alkanolamines, lactates and halides, such aschloride, can also be used as the ligand of the oxygen containingorganic ligand. In addition, the oxygen containing ligand can contain amixture of ligands selected alkoxides, acetyl acetonates, alkanolamines,lactates and halides.

Suitable methods for preparing the surface modifying treatment agentswherein the organo portion of the metal containing organic ligand isreactive with the organo-silicon containing material or fluorinatedhydrocarbon group are disclosed in U.S. Pat. Nos. 7,879,437 and8,067,103, herein incorporated by reference. In one embodiment, forinstance, the organo portion of the organometallic compound may beselected from those groups that may be reactive with the acids (or theirderivatives) of a perfluoroalkylene ether.

As an example, the surface modifying treatment agent could be preparedby mixing the metal containing organic ligand and the silicon-containingmaterial or fluorinated hydrocarbon in a closed system to avoidhydrolysis of the reactants. Reaction can occur neat or in the presenceof a non-reactive solvent such as chlorinated or fluorinated solvent,for example, methylene chloride. Heat may be used to initiate andcomplete the reaction. Solvent may be removed by evaporation and thereaction product can be redissolved in a suitable solvent such as analcohol, for example, ethanol or propanol, for application to thesubstrate. The mole ratio of the organosilicon-containing material tothe metal containing organic ligand is typically from 100:1 to 1:100,preferably from 1:1 to 10:1 depending on the valence of the metal of themetal containing organic ligand. For example, the molar ratio oforganosilicon compound to Ta(V) is typically 5 to 1.

In an embodiment, the surface modifying treatment agent may berepresented by the formula X_(a)(OR)_(b)M, wherein OR is a C₁ to C₁₈alkoxide, X is the hydrophobic tail represented by the organo-siliconmaterial or the fluorinated hydrocarbon, M is metal of the metalcontaining organic ligand and a+b equals the valency of M and furtherwherein neither a nor b are zero.

The composites disclosed herein may be prepared by mixing the solidparticulate and surface modifying treatment agent in a vessel at roomtemperature for a certain period of time, preferably from about 2 toabout 5 minutes. The solid can then be filtered and dried at roomtemperature, under vacuum or in an oven at a temperature between fromabout 100 to about 400° F., but preferably between from about 100 toabout 200° F., most preferably about 150° F. Alternatively the liquidmight be left with the solid and the mixture put in oven at atemperature between from about 100 to about 400° F., preferably betweenfrom about 100 to about 200° F., most preferably about 150° F. Theproduct is then cooled to room temperature. Alternatively, thecomposites may be prepared by use of fluidized bed or spray or dipcoating techniques.

The surface modifying treatment agent may be dissolved or dispersed in adiluent to form a solution. The solution may then be applied onto thesolid particulate. Suitable diluents include alcohols such as methanol,ethanol or propanol; aliphatic hydrocarbons such as hexane, isooctaneand decane, ethers, for example, tetrahydrofuran and dialkylethers suchas diethylether. Diluents for fluorinated materials can includeperfluorinated compounds such as perfluorinated tetrahydrofuran.

The surface modifying treatment agent of the composites is capable offorming an oleophilic surface onto the solid particulate. The oleophilicsurface is believed to facilitate the movement of aqueous treatmentfluid since water will be repelled by the oleophilic surface.

An adherent may be applied onto the solid particulate prior toapplication of the surface modifying treatment agent. The adherent maybe an adhesive or tackifying resin and serves to assist the adhesion ofthe surface modifying treatment agent onto the solid particulate. Theadherent may further be a layer which provides a reactive functionalgroup to the solid particulate.

In a preferred embodiment, an organometallic material is used asadherent. Such organometallic compounds include those derived from atransition metal, such as a Group IIIB metal or a transition metalselected from Group IVB, VB and VIB. Preferred transition metals aretitanium, zirconium, lanthanum, hafnium, tantalum and tungsten.

The organo portion of the organometallic may contain an alkoxide and/orhalides. Examples of suitable alkoxide groups are those containing from1 to 18 carbon atoms, preferably 2 to 8 carbon atoms, such as ethoxide,propoxide, isopropoxide, butoxide, isobutoxide and tertiary butoxide.Examples of suitable halides are fluoride and chloride. Other ligandswhich may also be present are acetyl acetonates.

Suitable organometallic compounds may be esters and polymeric forms ofthe esters including:

-   -   i. alkoxylates of titanium and zirconium having the general        formula M(OR)₄, wherein M is selected from Ti and Zr and R is        C₁₋₁₈ alkyl;    -   ii. alkyl esters of titanium and zirconium having the general        formula (X)_(4-y)-M(OR)_(y), wherein M is selected from Ti and        Zr; X is selected from fluorine and chlorine; R is C₁₋₁₈ alkyl        and y=2 to 3;    -   iii. polymeric alkyl titanates and zirconates obtainable by        condensation of the alkyl esters of (a), i.e., partially        hydrolyzed alkyl esters of the general formula        RO[-M(OR)(X)O—]_(y)R, wherein M, R and X are as above and y is a        positive integer,    -   iv. titanium chelates, derived from ortho titanic acid and        polyfunctional alcohols containing one or more additional        hydroxyl, halo, keto, carboxyl or amino groups capable of        donating electrons to titanium. Examples of these chelates are        those having the general formula        Ti(O)_(a)(OH)_(b)(OR′)_(c)(XY)_(d), wherein a=4−b−c−d;        b=4−a−c−d; c=4−a−b−d; d=4−a−b−c; R′ is H, R as above or X—Y,        wherein X is an electron donating group such as oxygen or        nitrogen and Y is an aliphatic radical having a two or three        carbon atom chain such as:        -   (a) —CH₂CH₂—, e.g., of ethanolamine, diethanolamine and            triethanolamine, or

-   -   -   (b) lactic acid,

-   -   -   (c) acetylacetone enol form, and

-   -   -   (d) 1,3-octyleneglycol,

    -   v. titanium acrylates having the general formula        Ti(OCOR)_(4-n)(OR)^(n) wherein R is C₁-18 alkyl as above and n        is an integer of from 1 to 3, and polymeric forms thereof, or

    -   vi. mixtures of (a) and (b).

The organometallic compound is usually dissolved or dispersed in adiluent. Examples of suitable diluents are alcohols such as methanol,ethanol and propanol, aliphatic hydrocarbons, such as hexane, isooctaneand decane, ethers, for example, tetrahydrofuran and dialkyl ethers suchas diethyl ether. Alternatively, the organometallic compound may beapplied to the solid particulate by vapor deposition techniques.

The concentration of the organometallic compound in the composition isnot particularly critical but is usually at least 0.001 millimolar,typically from 0.01 to 100 millimolar, and more typically from 0.1 to 50millimolar.

The adherent may be applied to the solid particulate by mixing all ofthe components at the same time with low shear mixing or by combiningthe ingredients in several steps. The organometallic composition may beapplied to the solid particulate by conventional means such as immersioncoating such as dipping, rolling, spraying or wiping to form a film. Thediluent is permitted to evaporate. This can be accomplished by heatingto 50-200° C.

The composite is especially useful in the treatment of sandstoneformations, carbonate formations and shale.

The composite may be pumped in a carrier or treatment fluid in order tofacilitate placement of the composite to a desired location within theformation. Any carrier fluid suitable for transporting the particulateinto a well and/or subterranean formation fracture in communicationtherewith may be employed including, but not limited to, carrier fluidsincluding a brine, salt water, unviscosified water, fresh water,potassium chloride solution, a saturated sodium chloride solution,liquid hydrocarbons, and/or a gas such as nitrogen or carbon dioxide.The composite may be pumped into the reservoir as a component of afluid. The fluid may be pumped into the formation at any time. Thus, forinstance, the composite may be pumped into the reservoir as a componentof a fracturing fluid, pad fluid, acidizing fluid, etc.

The concentration of the surface modifying treatment agent in a fluidpumped into the reservoir is typically between from about 0.01% to 100%or more typically between from about 0.1% to about 20% (v/v). In anembodiment, the composites may be used in slickwater fracturingoperations at relatively low concentrations.

The tail of the surface modifying treatment agent may align itself suchthat hydrophobicity of the surface modifying treatment agent is impartedaway from the surface of the solid particulate. Since the hydrophobictail of the surface modifying treatment agent is aligned away from thesolid particulate, the solid particulate can be more effectively used.

The composite improves wellbore productivity. In fracturing, thecomposite provides high-conductivity communication within the formation,thereby allowing for an increased rate of oil and gas production.Permeability of the formation is thus enhanced when the surfacemodifying treatment agent is attached onto the surface of the solidparticulate as compared to when the pristine (or untreated) solidparticulate is used by itself. Further, use of the disclosed compositeseffectively results in greater conductivity than when conventionalproppants are used.

Further, conductivity may be increased by use of the method disclosedherein since the hydrophobic tail effectively assists in removingresidual polymer. The increased conductivity may be attributable togreater effective propped fracture lengths. Greater effective proppedfracture length translates to improved stimulation efficiency, wellproductivity and reservoir drainage.

The composites are particularly effective in hydraulic fracturingoperations with a breaker, such as an enzyme breaker, to impartomniphobicity (hydrophobic and oleophobic characteristics) around thebreaker. This assists in the stability of the breaker especially at hightemperatures, such as in excess of 160° F., in some cases in excess of180° F. and in some in cases in excess of 220° F.

In such applications, the composite is directed toward improvingwellbore productivity and/or controlling the production of fractureproppant or formation sand.

The surface modifying treatment agent is also useful in the coating of aproppant pack in-situ. Packing of proppant may be dependent on theapparent specific gravity of the proppant. For instance, the packing maybe between from about 0.02 to about 0.8 lbs. per sq. ft for a proppantwith an apparent specific gravity between about 1.06 to about 1.5. Thepacking of proppant may cause an increase in porosity of the fracture.

In addition, the composites are effective as particulates in a gravelpacking operation. When used in sand control operations, the treatmentmay or may not employ a gravel pack screen, may be introduced into awellbore at pressures below, at or above the fracturing pressure of theformation, such as frac pack, and/or may be employed in conjunction withresins such as sand consolidation resins if so desired. As analternative to a screen, any other method in which a pack of particulatematerial is formed within a wellbore that it is permeable to fluidsproduced from a wellbore, such as oil, gas, or water, but thatsubstantially prevents or reduces production of formation materials,such as formation sand, from the formation into the wellbore may beused. The hydrophobic character of the composites disclosed hereinfurther enhance productivity by preventing migration of unconsolidatedformation particulates into the wellbore and to prevent flowback ofproppant or gravel pack particulates with produced fluids. The decreasedpropensity for flowback created by the composites may be accountable bythe consolidation of the particulates extended by the surface modifyingtreatment agent.

The presence of the surface modifying treatment agents on the solidparticulate further reduces frictional drag of fluids within thehydrocarbon producing reservoir. The frictional drag may be createdduring the turbulent flow of fluids within the well. Further, thereduction in frictional drag occurs during the pumping of producedhydrocarbons from the hydrocarbon producing reservoir. The reduction infrictional drag within the well is thus attributable to the bonding ofthe surface modifying treatment agent onto the surface of the solidparticulate. Thus, frictional drag is reduced and flow of hydrocarbon(or water phase) improved by the presence of the surface modifyingtreatment agent on the solid particulate.

In addition, the reduction in friction within the well provided by thesurface modifying treatment agent decreases the embedment or thepossibility of embedment of proppant within the formation. This isparticularly pronounced in shale formations.

When bound to the surface of the solid particulate, the sliding anglebetween fluids within the well and the composite is reduced compared toa pristine solid particulate not having the surface modifying treatmentagent. Fluid flow improvement has been evident in both hydrocarbon andaqueous phases. The reduction in sliding angle further is of benefit inenhancing load recovery of water by increasing the recovery of flowbackwater from the well after a fracturing fluid has been returned to thesurface.

As used herein, the sliding angle (also known as tilting angle) is ameasurement of the lateral adhesion of a drop of a fluid to the surfaceof a substrate. Thus, the sliding angle of a fluid on a substrate havinga surface modifying treatment agent bonded thereto is less than thesliding angle of the same fluid on the (same) substrate (“pristineunmodified substrate”) which does not have the surface modifyingtreatment agent bonded thereto. Where the surface modifying treatmentagent is bond only to a portion of the substrate, the sliding angle ofthe drop of fluid on the portion of the substrate having the surfacemodifying treatment agent bonded thereto is less than the sliding angleof the fluid on the substrate not having the surface modifying treatmentagent bonded thereto.

The reduction in frictional drag during the production of hydrocarbonsfrom the well may be measured by a reduction in the sliding angle of thefluid with the formation surface. The reduction in adhesion bondstrength results in reduced drag between the liquid and the solidsurface, allowing for easier fluid flow at a given stress. The decreasein sliding angle accelerates the flow of fluid from the well bylessening the amount of fluid trapped within the formation.

In an embodiment, the sliding angle of a fluid to a surface of the solidparticulate treated with the surface modifying treatment agent may beless than or equal to 60′; in some cases less than or equal to 20′; inother cases less than or equal to 10° and in some other cases less thanor equal to 5°. In one instance, the sliding angle for hydrocarbons hasbeen observed to be less than 10°. In another instance, the reduction inlateral adhesion of a fluid has been observed by a reduction in thesliding angle from 80° (non-treated substrate) to 40° (treatedsubstrate).

The reduction in sliding angle is independent of the contact angle. Thecontact angle refers to the angle between a drop of the liquid and thesurface of the solid particulate. A high contact angle reduces thenormal adhesion of a liquid droplet to the solid surface due to areduction of the liquid-solid contact area.

The contact angle is a measure of hydrophobicity. Typically, a liquid isconsidered to be “non-wet” or hydrophilic when the contact angle is lessthan 90° and “non-wetting” or hydrophobic when the contact angle isgreater than 90°. A surface having a water contact angle greater than150° is usually termed “ultra-hydrophobic” characterizing awater-repellant surface. A superhydrophobic surface may have a contactangle hysteresis less than 10°; in some cases less than 5°. When thecontact angle is less than 90°, the wetting tendency of the surfacemodified substrate may greater when the substrate is rough versussmooth. When the contact angle is greater than 90°, the substrate mayrepel more when the substrate is rough.

Since hydrophobicity prevents the formation of water blocks on thesurface of the substrate, the contact angle is indicative of thecapillary pressure within the substrate. Whereas the contact angle isrepresentative of static conditions, the sliding angle is representativeof fluid movement downhole. No relationship can be drawn between thecontact angle and sliding angle. As such, the contact angle provides noindication of the sliding angle. Improvement in frictional drag has beenseen with a reduced sliding angle and a contact angle less than or equalto 20°. Further, improvements in frictional drag have been observed witha reduced sliding angle and a contact angle greater than or equal to120°. For instance, the effectiveness of surface modifying treatmentagents on substrate surfaces to reduce frictional drag has been seenwith fluids exhibiting a contact angle less than 20° and a sliding angleless than 20° and a contact angle greater than 120° and a sliding angleless than 20°.

The amount of fines or dust typically generated from a pristine solidparticulate under in-situ conditions may be reduced by attaching thesurface modifying treatment agent to at least a portion of the surfaceof the solid particulate. For instance, the amount of fines generatedduring pumping of a proppant or sand control particulate into a well isless when the surface modifying treatment agent is attached to at leasta portion of the solid particulate than the amount of fines generatedduring pumping the of the pristine proppant or sand control particulateinto the well.

The decrease in the generation of fines and/or dust may further beattributable to friction reduction within the well imparted by thepresence of the surface modifying treatment agent on the surface of thesolid particulate. As described, the particulate may be pumped into thewell first and the surface modifying treatment agent then pumped intothe well to coat the particulate in-situ. The amount of fines and/ordust generated from the solid particulate is reduced by the surfacemodifying treatment agent.

When the particulates are present within the formation as a pack, theamount of fines generation and thus damage to the formation or operationwhich normally attributable to the spalling of fines from theparticulate pack within the formation may be minimized when theparticulates of the pack are coated with the surface modifying treatmentagent than when the particulates are in their pristine state.

In addition to minimizing the generation of fines and/or dust during awell treatment operation, the composites may be used to prevent sandgrains as well as formation fines from migrating into the wellbore.

The composite may also be used in treatments near wellbore in nature(affecting near wellbore regions). In an embodiment, the composites maybe used as packers or isolation profilers and in effectuating zonalisolation within a formation. Seals exposed to the composites definedherein may have reduced contact area with fluids within the wellbore.This reduced contact area may improve the lifetime of the seals. Inselective simulation operations, the solid particulate is preferablyelastomeric.

The surface modifying treatment agent further protects the solidparticulate from invasive organic and inorganic chemicals and othersubterranean environmental factors that decrease the life and thereliability of the particulate, such as temperatures and pressures.

The surface modifying treatment agent coated onto the solid particulatefurther reduces friction between tubular and other metallic substrateswithin the well. When used in fracturing, the composite may minimizefriction reduction and thus assist in maintaining viscosity of the fluidupon contact with hydrocarbons and adverse environmental factors.Further, the composite is subjected to less grinding within the well atin-situ conditions in light of the reduction in friction.

The hydrophobic tail of the surface modifying treatment agent mayprovide reduced surface energy, such that water and other liquids may berepelled. As such, such surface may be “self-cleaning,” meaning thatwater and other liquids rolling off the composites may remove unwantedmaterials. For example, corrosive materials used in drilling may beremoved from earth-boring tools in the presence of the composites thantools exposed to such composites. Upon removal from a wellbore, toolsexposed to the disclosed composites may be cleaner than tools notexposed to such composites and may therefore require less effort toproperly clean and store them.

In addition, wellbore operation tools may be exposed to lower frictionalforces against formation materials. Thus, such tools may require lowerpump pressures and flow rates to operate than similar tools withoutbeing exposed to the disclosed composites.

The presence of such composites in flow lines may further provide lessfrictional forces on fluids traveling through them. Thus, pressurelosses within flow lines containing the composites may be lower thanpressure losses in flow lines not exposed to such composites. Thecomposites thus offer the ability to use smaller pumps, smaller flowlines, or drilling in regions which require higher pressure.

Any of the solid particulates described herein as the solid particulateof the composite may also be used as a (pristine) particulate incombination with the composite. For instance, a composite as describedherein having a ceramic as the solid particulate (onto which a surfacemodifying treatment agent has been applied) may also be used incombination with a conventional or untreated ceramic proppant. The solidparticulate of the composite and the proppant used in admixture with thecomposite does not have to be the same material. Any combination may beacceptable. For instance, a composite of a ceramic particulate and asurface modifying treatment agent may be admixed with sand. A compositeof a sand particulate and surface modifying treatment agent may be usedin combination with a nylon proppant and so on.

The hydrophobic tail of the composite disclosed herein may be alsoeffective to passively inhibit, control, prevent or remove scaledeposition onto or within the formation. The hydrophobic tail minimizesor decreases the ability of such materials to adhere to the formation.This may be attributable to the hydrophobic nature of such mineralsscales as calcium, barium, magnesium salts and the like including bariumsulfate, calcium sulfate, and calcium carbonate scales. The compositesmay further have applicability in the treatment of other inorganicscales, such as metal sulfide scales, like zinc sulfide, iron sulfide,etc. Since such scales tend to plug the pore spaces and reduce theporosity and permeability of the formation, the surface modifyingtreatment agent described herein improves the permeability of theformation.

The bulky nature of the hydrophobic tail of the composites further mayassist, prevent or control deposition of organic particulates onto theformation substrate. This may assist in the return of fines the surfacewith produced fluid.

In addition, the hydrophobic tail of the composites disclosed hereinminimizes binding sites for organic particulates within the well. Thus,the composites may be used to control or prevent the deposition oforganic materials (such as paraffins and/or asphaltenes) within or ontothe formation. Such solids and particulates are known to negativelyimpact the overall efficiency of completion of wells and, like scaleinhibitors, can precipitate from produced water and create blockages inflow paths within the formation. The formation and deposition of suchunwanted contaminants decrease permeability of the subterraneanformation, reduce well productivity, and, in some cases, may completelyblock well tubing.

The composite may further serve a passive anti-microbial function inorder to counter bacterial growth principally caused by nitrogen and/orphosphorus in formation water or within fluid injected into theformation. The hydrophobicity of the composite may repel the fluid fromthe formation and thus decreases contact time of the fluid in theformation. This prevents the build-up of aerobic bacteria, anaerobicbacteria and other microbials.

Thus, by functioning as well treatment additives, the composites offeradvantages to operators since they often minimize or eliminate the needfor such components. This also facilitates mixing operations on the fly.This is especially the case where limited space is available tooperators.

Further, the composites of the disclosure may be used in remedial fluids(such as an acidizing fluid or a scale inhibition fluid, or a gravelpack fluid). The omniphobicity offered by the tail of the surfacemodifying treatment agent is of benefit during clean-up of the well andfluids within the well, such as fracturing fluids.

Further, the tail of the surface modifying treatment agent may also beused in remedial workovers of wells in order to keep silicates insuspension and to remove clay, fine and sand deposits as well asinorganic scales from downhole screens and from drilling fluid damage.The hydrophobic tail of the composite minimizes the formation of calciumfluoride and magnesium fluoride or sodium or potassium fluorosilicate orfluoroaluminate within the well. Such action further provides a remedialsolution having minimal downtime at low costs.

Further, the hydrophobic nature of the tail of the composite alters thewetability of the surface of the solid particulate. Thus, when used as aproppant or sand control particulate, the hydrophobic layer coated ontothe particulate lowers the water saturation and enhances recovery ofwater from the formation.

In addition, the hydrophobic tail of the surface modifying treatmentagent may alter the surface energy of the proppant or sand controlparticulate. The reduction in surface energy is likely the resultant ofreduced charge density on the surface of the composite. Production ofhydrocarbons from the formation is therefore improved by use of thecomposite disclosed herein.

The well treatment composite disclosed here may be prepared on locationby spraying or mixing the solid particulates and letting them react forat least five minutes for the surface modification reaction to takeplace before placement into the wellbore. A primer may also be appliedonto the solid particulate prior to application of the surface modifyingtreatment agent. The primer may be an adhesive or tackifying resin andserves to assist the adhesion of the surface modifying treatment agentonto the solid particulate. The primer may be an organometallic compoundsuch as those referenced herein. In such case, the organo portion of theorganometallic preferably contains an alkoxide and/or halide.

Preferred embodiments of the present disclosure thus offer advantagesover the prior art and are well adapted to carry out one or more of theobjects of this disclosure. However, the present disclosure does notrequire each of the components and acts described above and are in noway limited to the above-described embodiments or methods of operation.Any one or more of the above components, features and processes may beemployed in any suitable configuration without inclusion of other suchcomponents, features and processes. Moreover, the present disclosureincludes additional features, capabilities, functions, methods, uses andapplications that have not been specifically addressed herein but are,or will become, apparent from the description herein, the appendeddrawings and claims.

All percentages set forth in the Examples are given in terms of weightunits except as may otherwise be indicated.

EXAMPLES Example 1

Permeability testing was performed on synthetic cores composed of 20-40Carbolite proppant and 80-100 mesh silica sand. Each of the syntheticcores was 1.0″ in diameter and 2.0″ in length and having nitrogenpermeability of 100 and was saturated with ISOPAR™ paraffinic fluid.Each of the cores was then installed in a hydrostatic core holderapparatus and tested individually. Approximately 200 psi back pressurewas applied at the exit end and approximately 1,000 psi confining stress(overburden pressure) was applied around the entire cylinder. Theconfining stress pressure simulates stress in the downhole formation. Anaqueous solution of 2% potassium chloride (KCl) was then flowed throughthe core in order to establish baseline permeability to the water atresidual oil saturation. Following establishment of baseline waterpermeability, ISOPAR™ paraffinic fluid was flowed through the core untila baseline permeability to oil was established at irreducible watersaturation. Pressure drop was measured across the entire length of thecore and was used to calculate individual baseline permeability to waterand to oil.

A five pore volume of a neat fluid of H1-F was then injected into thecore and allowed to soak for about one hour in the 20-40 Carbolite.After treatment, paraffinic fluid was flowed through the core andpermeability of oil at irreducible water saturation was then measuredand the percent retention in permeability was then determined. Afteroil, water was flowed measuring permeability of water at residual oilafter treatment and comparing that to the water right before treatment.As such, the oil at irreducible water saturation and the water atresidual oil saturation were measured and the percent retention inpermeability was then determined.

A second core 80-100 mesh silica sand already surface modified with H1-Fwas prepared. The silica sand and H1-F was mixed together for about fiveminutes, and then the mixture was put in the oven overnight until thesand was completely dried. The core was made after the sand cooled downto room temperature following the method described previously. The corewas first saturated in paraffinic fluid then loaded into the hydrostaticcore holder at the same conditions as previous. Water was flowedmeasuring permeability of water at residual oil after treatment andcomparing that to the water right before treatment. After water,paraffinic oil was flowed through the core and permeability of oil atirreducible water saturation was then measured and the percent retentionin permeability was then determined. As such, the oil at irreduciblewater saturation and the water at residual oil saturation were measuredand the percent retention in permeability was then determined.

Retention in permeability in the synthetic core containing 20-40Carbolite proppant and 80-100 mesh silica sand is illustrated in FIG. 3.

Example 2

Gel recovery in proppant/gravel pack was determined by weighing onekilogram of particles, than packing them in a 12 inches long, 2 inchesin diameter column. Three liters of deionized water, followed by twoliters of linear gel (40 ppt, lb per thousand gallon,) HEC and 3 litersof water were run through the pack. The differential pressure wasrecorded and used to calculate the percent permeability.

Three sample were tested: (1) silica sand (control frac sand); (2)E-modified silica sand (E-Mod Frac Sand) and (3) H1-F modified silicasand (H1-F Mod Frac Sand). The surface modified silica sand wereprepared by mixing the sand with the solution containing the surfacetreatment, mixing for about five minutes than drying in an ovenovernight at 150° F. The samples were cooled down before use.

Permeability recovery in the proppant/gravel (treated and untreated)after exposing the pack to water, linear gel and then water isillustrated in FIG. 4.

The methods that may be described above or claimed herein and any othermethods which may fall within the scope of the appended claims can beperformed in any desired suitable order and are not necessarily limitedto any sequence described herein or as may be listed in the appendedclaims. Further, the methods of the present disclosure do notnecessarily require use of the particular embodiments shown anddescribed herein, but are equally applicable with any other suitablestructure, form and configuration of components.

Example 3

White Northern Sand, commercially available from Unimin Corporation,having a size of 20/40 mesh (proppant) was modified using three surfacemodifying treatment agents. Each of the surface modifying treatmentagents, available from Aculon, Inc., had a hydrophobic tail and ananchor. The surface modifying treatment agents may be identified as H1-Fand Aculon E [comprising 2% of a treatment agent having a transitionmetal (anchor) linked to a fluorinated hydrocarbon tail in an organicsolvent] and AL-B [comprising 2% of an organophosphonate (anchor) havinga hydrocarbon polymeric hydrophobic tail in an organic solvent blend].Aculon-E and AL-B exhibits hydrophobic and oleophobic properties whileH1-F exhibits hydrophobic properties only. 1.5 kg of sand was mixed withthe surface modifying treatment agent for 5 minutes at room temperature.Coating of the surface modifying treatment agent onto the surface of theproppant proceeded by self-assembly of monolayers. Such self-assembledmonolayers (SAMs) provided highly ordered molecular assemblies whichformed spontaneously by chemisorption and self-organization of longchain molecules having hydrophobic and oleophobic groups onto thesurface of the proppant. The hydrophobic and oleophobic groups wereanchored onto the surface of the proppant through a condensationreaction with the oxygen species on the surface of the sand, thusproviding a strong covalent bond. This further increased the longevityof the lifespan of the surface of the particulate. Self-assembly of thesurface modifying treatment agent onto the surface of the proppantrendered a coating approximately 4 to 20 nm thick. The proppant havingthe coated SAMs were then kept in an oven at 150° F. until completelydry. After the sample was cooled, it was split accordingly to API RP 56,and crush tests were performed. Table 1 show the results obtained for6,000 and 7,000 psi crush tests for uncoated and surface modified sand.

TABLE 1 % fines- Stress Control % fines H1-F % fines E- % fines AL-B(PSI) Sample modified sand modified sand modified sand 6,000 8.36 4.815.13 4.40 7,000 12.25 8.72 9.23 10.50From the data it is clearly seen that the coated sand has a bettertolerance to stress than uncoated sand, as the percent of finesdramatically decrease.

While exemplary embodiments of the disclosure have been shown anddescribed, many variations are possible within the scope of the appendedclaims and may be made and used by one of ordinary skill in the artwithout departing from the spirit or teachings of the invention andscope of appended claims. Thus, all matter herein set forth or shown inthe accompanying drawings should be interpreted as illustrative, and thescope of the disclosure and the appended claims should not be limited tothe embodiments described and shown herein.

Preferred embodiments of the present disclosure thus offer advantagesover the prior art and are well adapted to carry out one or more of theobjects of this disclosure. However, the present disclosure does notrequire each of the components and acts described above and are in noway limited to the above-described embodiments or methods of operation.Any one or more of the above components, features and processes may beemployed in any suitable configuration without inclusion of other suchcomponents, features and processes. Moreover, the present disclosureincludes additional features, capabilities, functions, methods, uses andapplications that have not been specifically addressed herein but are,or will become, apparent from the description herein, the appendedclaims.

The methods that may be described above or claimed herein and any othermethods which may fall within the scope of the appended claims can beperformed in any desired suitable order and are not necessarily limitedto any sequence described herein or as may be listed in the appendedclaims. Further, the methods of the present invention do not necessarilyrequire use of the particular embodiments shown and described herein,but are equally applicable with any other suitable structure, form andconfiguration of components.

Variations, modifications and/or changes of the composites and methodsof the present invention, such as in the components, details ofconstruction and operation are possible may be made and used by one ofordinary skill in the art without departing from the spirit or teachingsof the invention and scope of appended claims. Thus, all matter hereinset forth should be interpreted as illustrative, and the scope of thedisclosure and the appended claims should not be limited to theembodiments described and shown herein.

What is claimed is:
 1. A composite for treating a well wherein thecomposite comprises a surface modifying treatment agent at leastpartially coated onto a solid particulate and wherein the surfacemodifying treatment agent comprises a metallic anchor and a hydrophobictail wherein the hydrophobic tail is an organo-silicon material, afluorinated hydrocarbon or both a hydrophobic organo-silicon materialand a fluorinated hydrocarbon and further wherein the metallic anchor ofthe surface modifying treatment agent is attached to the solidparticulate.
 2. The composite of claim 1, wherein the hydrophobic tailis a derivative of a silane, polysiloxane or a polysilazane.
 3. Thecomposite of 1, wherein the metal of the metallic anchor is a Group 3,4, 5, or 6 metal.
 4. The composite of claim 3, wherein the metal of themetallic anchor is selected from the group consisting of Ti, Zr, La, Hf,Ta, W and Nb.
 5. The composite of claim 1, wherein the hydrophobic tailis a derivative of an organo-silicon of the formula:R¹ _(4-x)SiA_(x) or (R¹ ₃S)_(y)B or an organo(poly)siloxane ororgano(poly)silazane of the formula:

where: R¹ are identical or different and are a hydrocarbon orsubstituted hydrocarbon radical containing from 1 to 100 carbon atoms; Ais hydrogen, halogen, OH, OR² or

Bis NR³ _(3-y); R² is a hydrocarbon or substituted hydrocarbon radicalcontaining from 1 to 12 carbon atoms; R³ is hydrogen or R¹; x is 1, 2 or3; and y is 1 or
 2. 6. The composite of claim 1, wherein the fluorinatedhydrocarbon contains the structure:

where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6; R² is alkylcontaining from 1 to 4 carbon atoms and p is 0 to
 18. 7. The compositeof claim 1, wherein the fluorinated hydrocarbon is of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 6, Y is F orC_(n)F_(2n); b is at least 1;m is 0 to 6 and p is 0 to
 18. 8. Thecomposite of claim 2, wherein the organo(poly)siloxane ororgano(poly)silazane has units of the formula:

where R¹ are identical or different and are a hydrocarbon or substitutedhydrocarbon radical containing from about 1 to about 12 carbon atoms;and R³ is hydrogen or R¹.
 9. The composite of claim 1, wherein thehydrophobic tail contains units of R⁵ ₂SiO₂ where R⁵ is halogen.
 10. Thecomposite of claim 1, further comprising an adherent between the solidparticulate and the metallic anchor of the surface modifying agent forbonding the metallic anchor to the solid particulate.
 11. The compositeof claim 10, wherein the adherent is an organometallic compound.
 12. Thecomposite of claim 11, wherein the organometallic compound comprises atransition metal selected from the group consisting of titanium,zirconium, lanthanum, hafnium, tantalum and tungsten and mixturesthereof.
 13. The composite of claim 1, wherein the solid particulate isselected from the group consisting of ceramics, sand, minerals, nutshells, gravel, polymeric particles, and mixtures thereof.
 14. Themethod of claim 13, wherein the polymeric particles are beads or pelletsof polystyrene, nylon, polystyrene divinylbenzene, polyethyleneterephthalate or a combination thereof.
 15. The composite of claim 13,wherein the solid particulate further has a resinous coating.
 16. Aproppant or sand control particulate comprising the composite ofclaim
 1. 17. The composite of claim 1, wherein the solid particulatecomprises an elastomer.
 18. The composite of claim 17, wherein theelastomer is selected from the group consisting of natural rubber,ethylene-propylene-diene polymers (EPDM), nitrile rubbers, carboxylatedacrylonitrile butadiene copolymers, polyvinylchloride-nitrile butadieneblends, chlorinated polyethylene, chlorinated sulfonate polyethylene,aliphatic polyesters having chlorinated side chains, polyacrylaterubbers, ethylene-acrylate terpolymers, copolymers of ethylene andpropylene, and optionally with one or more other ethylenicallyunsaturated monomers, ethylene vinyl acetate copolymers, fluorocarbonpolymers and copolymers, polyvinyl methyl ether, butadiene rubber,polychloroprene rubber, polyisoprene rubber, polynorbornenes,polysulfide rubbers, polyurethanes, silicone rubbers, vinyl siliconerubbers, fluoromethyl silicone rubber, fluorovinyl silicone rubbers,phenylmethyl silicone rubbers, styrene-butadiene rubbers, copolymers ofisobutylene and isoprene or butyl rubbers, brominated copolymers ofisobutylene and isoprene and chlorinated copolymers of isobutylene andisoprene and mixtures thereof.
 19. The composite of claim 18, whereinthe elastomer is natural rubber or a polymer of at least one of themonomers selected from the group consisting of vinylidene fluoride,hexafluoropropylene, tetrafluoroethylene, chlorotrifluoroethylene,perfluoro(alkyl vinyl ether).
 20. A method for treating a wellpenetrating a subterranean formation, comprising introducing into thewell the composite of claim 1 or forming the composite in-situ in thewell.
 21. The method of claim 20 wherein at least one of the followingconditions prevail: (a) the surface modifying treatment agent functionsas a passive anti-microbial agent; (b) the surface modifying treatmentagent functions to passively inhibit or control scale deposition onto orwithin the subterranean formation; (c) the surface modifying treatmentagent of the composite passively prevents or controls deposition oforganic particulates onto or within the surface of the subterraneanformation; or (d) the surface modifying treatment agent of the compositecontrols proppant flowback.
 22. The method of claim 20, wherein thecomposite is pumped into the well during a hydraulic fracturingoperation and further wherein the solid particulate is capable ofwithstanding stresses greater than about 1500 psi at a temperaturegreater than 150° F.
 23. The method of claim 20, wherein the compositeis formed in-situ in the well by first pumping the solid particulateinto the well and then at least partially coating the solid particulateby subsequently pumping the surface modifying treatment agent into thewell.
 24. A composite for treating a wellbore, wherein the compositecomprises a solid particulate and a surface modifying treatment agent atleast partially coated onto a solid particulate, the surface modifyingtreatment agent comprising an anchor and at least one hydrophobic tailattached to the anchor wherein the anchor is attached to the solidparticulate.
 25. The composite of claim 24, wherein the surfacemodifying treatment agent is a reaction product of an organometalliccompound having an oxygen ligand and an organo-silicon containingmaterial.
 26. The composite of claim 24, wherein the surface modifyingtreatment agent is of the formula X-M where M is a metal containingorganic ligand and X is a hydrophobic tail.
 27. A method for treating awell penetrating a subterranean formation, comprising introducing intothe well the composite of claim 24 or forming the composite in-situwithin the well.
 28. The method of claim 27, wherein the composite ispumped into the well or is formed in-situ within the well during ahydraulic fracturing operation or a sand control operation.
 29. Themethod of claim 27, wherein the formation penetrated by the well hasmultiple productive zones and wherein the composite isolates apre-determined productive zone from other zones of the well.
 30. Themethod of claim 27, wherein the composite minimizes tubular frictionpressures within the well.
 31. The method of claim 27, wherein theamount of fines and/or sand migrated during treatment of the well isdecreased by the presence of the surface modifying treatment agentcoated onto the solid particulate.
 32. The method of claim 27, whereinthe hydrophobic tail of the composite is aligned away from the surfaceof the solid particulate.
 33. The method of claim 27, wherein a fluidcontaining the composite is pumped into the well during a hydraulicfracturing operation and wherein the solid particulate is a proppant andfurther wherein the crush resistance of the proppant at a closure stressof 1,500 psi, AAPI 56 or API RP 60, is greater than the crush resistanceof a pristine proppant in a substantially similar, the pristine proppantnot having the surface modifying treatment agent at least partiallycoated onto the proppant.
 34. The method of claim 27, further comprisingproducing hydrocarbons from the well and reducing frictional drag duringhydrocarbon production.
 35. The method of claim 27, wherein the slidingangle of a fluid in the well on the surface of the composite is lessthan the sliding angle of the same fluid on the surface of a pristinesolid particulate not having the surface modifying treatment agentattached thereto.